Dynegy Inc. (NYSE: DYN) reported a net loss of $133 million for the
third quarter of 2017, compared to a net loss of $249 million for the
third quarter of 2016. Results for the most recent quarter benefited
from $86 million in contributions from assets acquired from ENGIE in
February 2017 and lower impairment charges, partially offset by losses
of $78 million related to the sale of assets and $66 million associated
with the early extinguishment of debt.

The Company reported consolidated Adjusted EBITDA of $397 million for
the 2017 third quarter compared to $350 million for the 2016 third
quarter. Contributions from the ENGIE assets were partially offset by
lower energy margin as a result of milder weather.

Net income for the first nine months of 2017 was $167 million compared
to a net loss of $1,062 million for the first nine months of 2016. The
year-to-date increase was primarily driven by contributions from the
ENGIE assets, income from a deferred tax valuation allowance release in
2017, a gain primarily due to the extinguishment of debt associated with
the Genco bankruptcy reorganization, and lower impairment charges,
partially offset by non-cash mark-to-market losses associated with
hedging transactions, acquisition and integration costs related to the
ENGIE acquisition, a loss on the sale of assets, and a loss on the early
extinguishment of debt.

For the first nine months of 2017, the Company reported consolidated
Adjusted EBITDA of $867 million compared to $788 million for the first
nine months of 2016. The $79 million increase in Adjusted EBITDA was
primarily driven by contributions from the ENGIE assets, partially
offset by lower energy margin largely driven by milder weather.

“During the third quarter, Dynegy’s power generation fleet produced the
highest generation volumes in the Company’s history while simultaneously
achieving top decile safety performance for the second quarter in a
row,” said Robert C. Flexon, Dynegy’s President and Chief Executive
Officer. “In addition to our operational achievements, we made
significant improvements to our balance sheet, reducing our outstanding
2019 maturity by $1.25 billion, with approximately half of that repaid
with asset sale proceeds and cash on hand.”

Third Quarter Comparative Results

Quarter Ended September 30,

2017

2016

(in millions)

OperatingIncome (Loss)

Adjusted EBITDA (1)

OperatingIncome (Loss)

Adjusted EBITDA (1)

PJM

$

86

$

243

$

29

$

215

NY/NE

(30

)

92

(15

)

55

ERCOT

50

46

—

—

MISO

(9

)

12

13

16

IPH

11

21

(104

)

50

CAISO

—

18

10

24

Other

(50

)

(35

)

(50

)

(10

)

Total

$

58

$

397

$

(117

)

$

350

__________________________________________

(1)

Adjusted EBITDA is a non-GAAP financial measure. See
“Regulation G Reconciliations” for further details.

Segment Review of Results Quarter-over-Quarter

PJM - Operating income for the 2017 third quarter totaled $86
million, compared to operating income of $29 million for the same period
of 2016. The increase was primarily due to income from the ENGIE assets,
higher capacity revenues as a result of higher pricing, an increase in
the mark-to-market value of derivative transactions and lower asset
impairments, partially offset by lower energy margin. Adjusted EBITDA
totaled $243 million during the 2017 third quarter compared to $215
million during the same period in 2016 primarily due to higher capacity
revenues and contributions from the ENGIE assets, partially offset by
lower energy margins.

NY/NE - Operating loss for the 2017 third quarter totaled $30
million, compared to operating loss of $15 million for the same period
in 2016. The increase was primarily due to a $77 million loss related to
the sale of the Dighton and Milford facilities in Massachusetts,
partially offset by income from the ENGIE assets, higher capacity
revenues as a result of higher pricing, and the change in the
mark-to-market value of derivative transactions. Adjusted EBITDA totaled
$92 million during the 2017 third quarter, compared to $55 million
during the same period in 2016, primarily due to the contributions from
the ENGIE assets.

ERCOT - Operating income for the 2017 third quarter totaled $50
million. Energy margin of $68 million and a mark-to-market gain of $23
million were partially offset by $23 million of O&M costs. Adjusted
EBITDA was $46 million.

MISO - Operating loss for the 2017 third quarter totaled $9
million, compared to an operating income of $13 million for the same
period in 2016. Contributing to the operating loss were lower dark
spreads as a result of milder weather, lower generation volumes as a
result of shutdowns in 2016, and higher depreciation expense. Adjusted
EBITDA totaled $12 million during the 2017 third quarter compared to $16
million during the same period in 2016. The decrease was primarily due
to lower dark spreads as a result of milder weather and lower generation
volumes due to shutdowns in 2016.

IPH - Operating income for the 2017 third quarter totaled $11
million, compared to operating loss of $104 million for the same period
of 2016. The year-over-year increase was primarily due to a $148 million
impairment charge on the Newton facility in the third quarter 2016,
partially offset by lower energy margin due to milder weather. Adjusted
EBITDA totaled $21 million during the 2017 third quarter compared to $50
million during the same period in 2016, primarily due to lower energy
margin as a result of milder weather.

CAISO - Operating income for the 2017 third quarter totaled $0
million, compared to operating income of $10 million for the same period
in 2016. The decrease in operating income was primarily due to lower
tolling revenue due to the expiration of a tolling agreement and lower
capacity revenues due to lower contracted volumes and prices, partially
offset by higher energy margin as a result of warmer weather. Adjusted
EBITDA totaled $18 million during the 2017 third quarter compared to
Adjusted EBITDA of $24 million during the same period in 2016.

Liquidity

As of September 30, 2017, Dynegy’s total available liquidity was
approximately $1.6 billion as reflected in the table below.

Cash provided by operations totaled $501 million for the first nine
months of 2017. During the period, our power generation facilities and
retail operations provided cash of $932 million. Corporate activities,
primarily related to general and administrative, interest and
acquisition-related expenses, as well as other working capital changes,
used cash of $431 million during the period.

Cash used in investing activities totaled $2,771 million during the
first nine months of 2017 as Dynegy used $3,249 million at the ENGIE
acquisition closing and invested $129 million in capital expenditures,
offset by $600 million proceeds received primarily related to the Troy
and Armstrong, and Milford-MA and Dighton sales, in addition to $7
million distributions received from our unconsolidated investment in
NELP.

Cash used in financing activities totaled $955 million for the first
nine months of 2017 primarily as a result of the remaining payment
obligation relating to the purchase of ECP’s interest in Atlas Power,
payments related to our Genco subsidiary’s emergence from bankruptcy as
well as various other financing activities.

The sale of Armstrong, Troy, Milford (MA), Dighton and Lee, together
with the later than expected closing of the ENGIE acquisition, has
impacted Adjusted EBITDA by approximately $70 million this year. As a
result we currently expect to be near the bottom of the Adjusted EBITDA
guidance range for the year.

PRIDE Update

Dynegy’s PRIDE Energized (Producing Results through Innovation by Dynegy
Employees) program is on track to meet or exceed its 2017 target of $65
million in EBITDA by the end of the fourth quarter. The Company has
already exceeded its three-year goal of $400 million in balance sheet
improvements with $422 million in improvements accomplished in 2016. For
2017, Dynegy has identified more than $100 million of incremental
balance sheet opportunities that will add to its aggregate total.

Safety

Dynegy’s safety performance for the third quarter 2017 was in the top
decile for the industry for the second consecutive quarter. Both coal
and gas facilities are focused on intensive safety initiatives helping
to drive safety culture. Dynegy expects that all of its plants will
complete the Voluntary Protection Program (VPP) process, a rigorous
evaluation conducted by the Occupational Safety and Health
Administration (OSHA), within the next three years. The Milford,
Connecticut facility went through the VPP certification renewal process
and was recommended for VPP recertification during the third quarter.

Retail Growth

Dynegy’s business has grown to serve approximately 1.2 million
residential and commercial accounts. The retail business expanded to New
England this summer with its municipal aggregation contracts in the
greater Boston area. The Company now provides electricity to more than
500 communities in Illinois, Massachusetts and Ohio.

Asset Portfolio Updates

PJM and ISO-NE Asset Sales

Since June 30, Dynegy has completed the sale of five generating
facilities, providing approximately $785 million in proceeds which were
used for debt reduction. In July, Dynegy completed the sales of the
Armstrong and Troy peaking units in Pennsylvania and Ohio, respectively,
to an affiliate of LS Power for approximately $480 million in cash. In
September, Dynegy completed the sale of the Dighton and Milford
intermediate gas-fueled plants in Massachusetts to an affiliate of
Starwood Energy Group Global for $125 million in cash including
approximately $6 million in working capital adjustments. In October,
Dynegy completed the sale of the Lee Energy Facility, a gas-fueled
peaking asset in the PJM ComEd region, to an affiliate of Rockland
Capital for $180 million in cash.

Earnings Presentation and Management Comments

Dynegy’s earnings presentation and management comments on the earnings
presentation will be available on the “Investor Relations” section of www.dynegy.com
later today. The Company will not be holding an investor conference call
and webcast.

About Dynegy

Throughout the Northeast, Mid-Atlantic, Midwest, and Texas, Dynegy
operates 27,000 megawatts (MW) of power generating facilities capable of
producing enough energy to supply more than 22 million American homes.
We generate power safely and responsibly for 1.2 million electricity
customers who depend on that energy to grow and thrive.

Forward-Looking Statements

This news release contains statements reflecting assumptions,
expectations, projections, intentions or beliefs about future events
that are intended as “forward-looking statements,” particularly those
statements concerning execution of Dynegy’s PRIDE Energized target in
balance sheet and operating improvements program; anticipated earnings
and cash flows, and Dynegy’s 2017 Adjusted EBITDA and Adjusted Free Cash
Flow guidance. Historically, Dynegy’s performance has deviated, in some
cases materially, from its cash flow and earnings guidance. Discussion
of risks and uncertainties that could cause actual results to differ
materially from current projections, forecasts, estimates and
expectations of Dynegy is contained in Dynegy’s filings with the
Securities and Exchange Commission (SEC). Specifically, Dynegy makes
reference to, and incorporates herein by reference, the section entitled
“Risk Factors” in its 2016 Form 10-K and subsequent Form 10-Qs. Any or
all of Dynegy’s forward-looking statements may turn out to be wrong.
They can be affected by inaccurate assumptions or by known or unknown
risks, uncertainties and other factors, many of which are beyond
Dynegy’s control. In addition to the risks and uncertainties set forth
in Dynegy’s SEC filings, the forward-looking statements described in
this press release could be affected by, among other things, (i) beliefs
and assumptions about weather and general economic conditions; (ii)
beliefs, assumptions, and projections regarding the demand for power,
generation volumes, and commodity pricing, including natural gas prices
and the timing of a recovery in power market prices, if any; (iii)
beliefs and assumptions about market competition, generation capacity,
and regional supply and demand characteristics of the wholesale and
retail power markets, including the anticipation of plant retirements
and higher market pricing over the longer term; (iv) sufficiency of,
access to, and costs associated with coal, fuel oil, and natural gas
inventories and transportation thereof; (v) the effects of, or changes
to the power and capacity procurement processes in the markets in which
we operate; (vi) expectations regarding, or impacts of, environmental
matters, including costs of compliance, availability and adequacy of
emission credits, and the impact of ongoing proceedings and potential
regulations or changes to current regulations, including those relating
to climate change, air emissions, cooling water intake structures, coal
combustion byproducts, and other laws and regulations that we are, or
could become, subject to, which could increase our costs, result in an
impairment of our assets, cause us to limit or terminate the operation
of certain of our facilities, or otherwise have a negative financial
effect; (vii) beliefs about the outcome of legal, administrative,
legislative, and regulatory matters, including any impacts from the
change in administration to these matters; (viii) projected operating or
financial results, including anticipated cash flows from operations,
revenues, and profitability; (ix) our focus on safety and our ability to
operate our assets efficiently so as to capture revenue generating
opportunities and operating margins; (x) our ability to mitigate forced
outage risk, including managing risk associated with CP in PJM and
performance incentives in ISO-NE; (xi) our ability to optimize our
assets through targeted investment in cost effective technology
enhancements; (xii) the effectiveness of our strategies to capture
opportunities presented by changes in commodity prices and to manage our
exposure to energy price volatility; (xiii) efforts to secure retail
sales and the ability to grow the retail business; (xiv) efforts to
identify opportunities to reduce congestion and improve busbar power
prices; (xv) ability to mitigate impacts associated with expiring
reliability must run “RMR” and/or capacity contracts; (xvi) expectations
regarding our compliance with the Credit Agreement, including collateral
demands, interest expense, any applicable financial ratios, and other
payments; (xvii) expectations regarding performance standards and
capital and maintenance expenditures; (xviii) the timing and anticipated
benefits to be achieved through our Company-wide improvement programs;
(xix) expectations regarding strengthening the balance sheet, managing
debt maturities and improving Dynegy’s leverage profile; (xx)
expectations, timing and benefits of the AES transaction; (xxi) efforts
to divest assets and the associated timing of such divestitures, and
anticipated use of proceeds from such divestitures; (xxii) anticipated
timing, outcome and impact of expected retirements; (xxiii) beliefs
about the costs and scope of the ongoing demolition and site remediation
efforts; and (xxiv) expectations regarding the synergies and anticipated
benefits resulting from the ENGIE Acquisition. Any or all of Dynegy’s
forward-looking statements may turn out to be wrong. They can be
affected by inaccurate assumptions or by known or unknown risks,
uncertainties, and other factors, many of which are beyond Dynegy’s
control.

The following table reflects significant components of our
weighted average shares outstanding used in the basic and diluted
loss per

share calculations for the three and nine months ended September
30, 2017 and 2016:

Three Months Ended September 30,

Nine Months Ended September 30,

(in millions)

2017

2016

2017

2016

Shares outstanding at the beginning of the period (1)

154

140

140

117

Weighted-average shares outstanding during the period of:

Shares issued under long-term compensation plans

—

—

1

—

Shares issued under the PIPE Transaction

—

—

11

—

Prepaid stock purchase contract (TEUs) (1)

—

—

—

9

Basic weighted-average shares outstanding

154

140

152

126

Dilution from potentially dilutive shares (2)

—

—

7

—

Diluted weighted-average shares outstanding (3)

154

140

159

126

_________________________________________

(1)

The minimum settlement amount of the TEUs, or 23,092,460 shares, is
considered to be outstanding since the issuance date of June 21,
2016, and is included in the computation of basic earnings (loss)
per share for the three and nine months ended September 30, 2017 and
2016.

(2)

Shares included in the computation of diluted earnings (loss) per
share for the nine months ended September 30, 2017 primarily consist
of approximately 5.4 million shares related to our TEUs.

(3)

Entities with a net loss from continuing operations are prohibited
from including potential common shares in the computation of diluted
per share amounts. Accordingly, we have utilized the basic shares
outstanding amount to calculate both basic and diluted loss per
share for the three months ended September 30, 2017 and three and
nine months ended September 30, 2016.

results of operations for the three and nine months ended September
30, 2017 and 2016, respectively.

Three Months EndedSeptember 30,

Nine Months EndedSeptember 30,

2017

2016

2017

2016

PJM

Million Megawatt Hours Generated (1)

14.5

15.1

38.8

39.3

IMA (1)(2):

Combined Cycle Facilities

98

%

97

%

93

%

97

%

Coal-Fueled Facilities

75

%

83

%

71

%

81

%

Average Capacity Factor (1)(3):

Combined Cycle Facilities

70

%

79

%

63

%

75

%

Coal-Fueled Facilities

62

%

65

%

54

%

51

%

CDDs (4)

787

1,044

1,085

1,377

HDDs (4)

34

17

2,606

3,056

Average Market On-Peak Spark Spreads ($/MWh) (5):

PJM West

$

23.21

$

31.48

$

16.79

$

23.79

AD Hub

$

24.95

$

27.27

$

18.05

$

28.88

Average Market On-Peak Power Prices ($/MWh) (6):

PJM West

$

35.10

$

40.74

$

33.62

$

34.77

AD Hub

$

36.30

$

38.75

$

33.76

$

32.66

Average natural gas price—TetcoM3 ($/MMBtu) (7)

$

1.70

$

1.32

$

2.40

$

1.57

NY/NE

Million Megawatt Hours Generated (1)

5.7

5.4

14.6

13.1

IMA for Combined Cycle Facilities (1)(2)

87

%

98

%

91

%

95

%

Average Capacity Factor for Combined Cycle Facilities (1)(3)

52

%

63

%

42

%

50

%

CDDs (4)

519

724

687

874

HDDs (4)

62

100

3,543

3,658

Average Market On-Peak Spark Spreads ($/MWh) (5):

New York—Zone C

$

18.52

$

26.04

$

13.30

$

17.37

Mass Hub

$

16.17

$

21.58

$

11.63

$

14.49

Average Market On-Peak Power Prices ($/MWh) (6):

New York—Zone C

$

29.86

$

34.79

$

29.01

$

26.74

Mass Hub

$

31.94

$

41.31

$

33.97

$

34.44

Average natural gas price—Algonquin Citygates ($/MMBtu) (7)

$

2.25

$

2.82

$

3.19

$

2.85

ERCOT

Million Megawatt Hours Generated (1)

5.0

—

8.8

—

IMA (1)(2):

Combined-Cycle Facilities

86

%

—

%

89

%

—

%

Coal-Fueled Facility

93

%

—

%

95

%

—

%

Average Capacity Factor (1)(3):

Combined-Cycle Facilities

47

%

—

%

30

%

—

%

Coal-Fueled Facility

75

%

—

%

63

%

—

%

CDDs (4)

1,701

1,808

3,026

2,909

HDDs (4)

—

—

509

788

Average Market On-Peak Spark Spreads ($/MWh) (5):

ERCOT North

$

12.65

$

14.51

$

8.16

$

10.60

Average Market On-Peak Power Prices ($/MWh) (6):

ERCOT North

$

31.21

$

33.25

$

27.17

$

25.72

Average natural gas price—Waha Hub ($/MMBtu) (7)

$

2.65

$

2.68

$

2.72

$

2.16

MISO

Million Megawatt Hours Generated

3.4

4.2

8.8

11.2

IMA for Coal-Fueled Facilities (2)

94

%

90

%

90

%

89

%

Average Capacity Factor for Coal-Fueled Facilities (3)

82

%

76

%

71

%

61

%

CDDs (4)

786

1,029

1,167

1,529

HDDs (4)

11

46

2,610

3,006

Average Market On-Peak Power Prices ($/MWh) (6):

Indiana (Indy Hub)

$

37.04

$

40.19

$

34.91

$

32.32

Commonwealth Edison (NI Hub)

$

34.03

$

38.41

$

32.49

$

31.54

IPH

Million Megawatt Hours Generated

4.6

5.0

12.6

11.6

IMA for IPH Facilities (2)

85

%

88

%

87

%

88

%

Average Capacity Factor for IPH Facilities (3)

62

%

59

%

57

%

45

%

CDDs (4)

786

1,029

1,167

1,529

HDDs (4)

11

46

2,610

3,006

Average Market On-Peak Power Prices ($/MWh) ($/MWh) (6):

Indiana (Indy Hub)

$

37.04

$

40.19

$

34.91

$

32.32

Commonwealth Edison (NI Hub)

$

34.03

$

38.41

$

32.49

$

31.54

CAISO

Million Megawatt Hours Generated

1.0

0.5

1.5

2.0

IMA for Combined Cycle Facilities (2)

86

%

92

%

85

%

96

%

Average Capacity Factor for Combined Cycle Facilities (3)

43

%

20

%

23

%

27

%

CDDs (4)

874

723

1,126

1,051

HDDs (4)

6

22

834

737

Average Market On-Peak Spark Spreads ($/MWh) (5):

North of Path 15 (NP 15)

$

23.84

$

15.44

$

13.89

$

12.32

Average natural gas price—PG&E Citygate ($/MMBtu) (7)

$

3.27

$

3.18

$

3.29

$

2.52

__________________________________________

(1)

Million Megawatt Hours Generated and Average Capacity Factor include
such activity for the full month of February. IMA excludes such
activity for our period of ownership in February.

(2)

IMA is an internal measurement calculation that reflects the
percentage of generation available during periods when market prices
are such that these units could be profitably dispatched. The
calculation excludes certain events outside of management control
such as weather related issues. The calculation excludes our Brayton
Point facility and CTs.

(3)

Reflects actual production as a percentage of available capacity.
The calculation excludes our Brayton Point facility and CTs.

(4)

Reflects CDDs or HDDs for the region based on NOAA data.

(5)

Reflects the simple average of the on-peak spark spreads available
to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead
prices and buying delivered natural gas at a daily cash market price
and does not reflect spark spreads available to us.

(6)

Reflects the average of day-ahead settled prices for the periods
presented and does not necessarily reflect prices we realized.

(7)

Reflects the average of daily quoted prices for the periods
presented and does not reflect costs incurred by us.

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

THREE MONTHS ENDED SEPTEMBER 30, 2017

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our
Adjusted EBITDA by segment for the three months ended September
30, 2017:

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please
refer to Item 2.02 of our Form 8-K filed on November 1, 2017, for
definitions, utility and uses of such non-GAAP financial measures. A
reconciliation of EBITDA to Operating income (loss) is presented
above. Management does not allocate G&A, interest expense and income
taxes on a segment level and therefore uses Operating income (loss)
as the most directly comparable GAAP measure.

(2)

Not adjusted to exclude Wood River’s energy margin and O&M costs.

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

THREE MONTHS ENDED SEPTEMBER 30, 2016

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our
Adjusted EBITDA by segment for the three months ended September
30, 2016:

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please
refer to Item 2.02 of our Form 8-K filed on November 1, 2017, for
definitions, utility and uses of such non-GAAP financial measures. A
reconciliation of EBITDA to Operating income (loss) is presented
above. Management does not allocate G&A, interest expense and income
taxes on a segment level and therefore uses Operating income (loss)
as the most directly comparable GAAP measure.

(2)

Other includes an adjustment to exclude Wood River’s energy margin
and O&M costs of $3 million.

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please
refer to Item 2.02 of our Form 8-K filed on November 1, 2017, for
definitions, utility and uses of such non-GAAP financial measures. A
reconciliation of EBITDA to Operating income (loss) is presented
above. Management does not allocate G&A, interest expense and income
taxes on a segment level and therefore uses Operating income (loss)
as the most directly comparable GAAP measure.

EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please
refer to Item 2.02 of our Form 8-K filed on November 1, 2017, for
definitions, utility and uses of such non-GAAP financial measures. A
reconciliation of EBITDA to Operating income (loss) is presented
above. Management does not allocate G&A, interest expense and income
taxes on a segment level and therefore uses Operating income (loss)
as the most directly comparable GAAP measure.

(2)

Other includes an adjustment to exclude Wood River’s energy margin
and O&M costs of $23 million for the nine months ended September 30,
2016.